This disclosure relates generally to the field of subsurface formation fracture evaluation. More specifically, the disclosure relates to techniques for detecting fractures having a planar orientation substantially perpendicular to a wellbore using multi-axial electromagnetic induction well logging instruments.
A multi-axial electromagnetic induction well logging instrument such as a triaxial electromagnetic induction well logging instrument sold under the trademark RT SCANNER, which is a trademark of Schlumberger Technology Corporation, Sugar Land, Texas, measures 9-component apparent conductivity tensors (σm(i, j, k), i, j=x, y, z) at a plurality of receiver spacings from a transmitter, wherein each spacing is represented by the index k. FIG. 2 schematically illustrates such a tri-axial tool 10 and the component tensor measurement C. The instrument 10 may include one or more multi-axial electromagnetic transmitters T disposed on the instrument 10, and have one or more multi-axial electromagnetic receivers (each receiver usually consisting of a main receiver RM and a balancing or “bucking” receiver RB to attenuate direct induction effects) at one or more axially spaced apart positions along the longitudinal axis z of the tool 10. The RT SCANNER instrument uses triaxial transmitters and receivers, wherein the transmitters and receivers have three, mutually orthogonal coils having magnetic dipole axes oriented along the tool axis z and along two other mutually orthogonal directions shown at x and y. The instrument measurements in the present example may be obtained in the frequency domain by energizing the transmitter T with a continuous wave (CW) alternating current having one or more discrete frequencies (using more than one discrete frequency may enhance the signal-to-noise ratio). However, measurements of the same information content may also be obtained using time domain signals through a Fourier decomposition process by energizing the transmitter T with one or more types of transient currents. This is a well known physics principle of frequency-time duality. Voltages induced in each coil of one of the receivers RM/RB is shown in the tensor C represented by the voltage V with a two letter subscript as explained above representing the axis (x, y or z) of the transmitter coil used and the axis of the receiver coil (x, y or z) used to make the particular voltage measurements. The voltage measurements in tensor C may be processed to obtain the described apparent conductivity tensors. Subsurface formation properties, such as horizontal and vertical conductivities (σh, σv) or their inverse, horizontal and vertical resistivities (Rh, Rv), relative dip angle (θ) and the dip azimuthal direction (Φ), as well as borehole/tool properties, such as drilling fluid (mud) conductivity (σmud), wellbore diameter (hd), tool eccentering distance (decc), tool eccentering azimuthal angle (ψ), all affect the measurements of voltages used to determine the conductivity tensors.
FIG. 3A illustrates a top view, and FIG. 3B shows an oblique view of an eccentered tool 10 in a wellbore 12 drilled through an anisotropic formation F with a non-zero dip angle (θ). Eccentering of the tool 10 is shown by decc and the azimuthal angle of the dip azimuth is represented by (ψ). The tool 10 eccentering azimuthal angle is shown by ψ. FIG. 3C shows vertical and horizontal conductivity determinable with the tool of FIGS. 3A and 3B with reference to a dip angle between formation layering and a wellbore (and corresponding tool) longitudinal axis. The above description is to provide a frame of reference to understand an example method according to the present disclosure.
Using a simplified model of layered anisotropic formation traversed obliquely by the wellbore 12, the response of the conductivity tensors depends on the above eight parameters in a very complex manner. The effects of the wellbore and instrument orientation and position on the measured conductivity tensors may be very large even in wellbores having substantially electrically nonconductive fluid therein, e.g., oil base mud (OBM). Through one of several known inversion techniques the above wellbore and formation parameters can be calculated and borehole effects can be removed from the measured conductivity tensors to determine values of horizontal and vertical resistivities (Rh, Rv), relative dip angle (θ) and the dip azimuthal direction (Φ).
The formation parameters (vertical and horizontal conductivities, dip and dip azimuth) may be displayed substantially in real-time (as computed by a processor near the wellbore, see FIG. 1A and FIG. 1B) to help make various decisions related to the drilling and completion of the wellbore. The resistivities (the inverse of conductivities) of the subsurface formations determinable by a tool such as illustrated in FIG. 2 are known in the art to be used, for example, to delineate low resistivity laminated hydrocarbon bearing formations. The dip and dip azimuth are known to be used to map the structure of the formations in a scale much finer than that provided by, e.g., surface reflection seismic.
One of the important items of information that may affect the drilling and completion decisions of any particular wellbore is whether the wellbore has traversed significant fractured zones. Fractures may occur in some formations due to tectonic forces acting over geological time. Fractures can also be induced in some formations by the drilling operation. Large fracture systems can sometimes be a principal factor that enables economically useful production of oil and/or gas from a particular wellbore. Large fracture systems traversed by a wellbore could also cause loss of drilling mud. Accordingly, knowing the location of the fracture zone and the fracture plane orientation can significantly improve the drilling and completion decision.
Fractures with large planar extent, even if very thin, filled with non-conductive fluid, such as connate oil and/or oil based drilling fluid may block the induced current in the formation resulting from electromagnetic induction effects of energizing the transmitter T on the tool and could produce significant anomalies in the inverted formation parameters compared with those from the same formation without fractures. The size of such anomalies may depend on the formation resistivities (Rh, Rv), the size of the fracture plane, and the relative dip and azimuth between the fracture plane and the layering structure of the formation, among other factors. If the fracture plane is nearly parallel to the layering structure of the formation, the effects of the fracture on measurements made by an instrument such as shown in FIG. 2 may be relatively small. On the other hand, if the fracture plane is perpendicular to the layering structure of the formation, the effect of the fracture may dominate the response of the tool. A fracture system often encountered by wellbores is that of substantially horizontal layered formations with vertical fractures. Accordingly, techniques for characterizing such fractures using multi-axial (e.g., tri-axial) electromagnetic induction measurements may be useful in this regard.